One of the main issues in examining the petrophysical properties of a geologic formation is the ability of the measuring device to differentiate between individual fluid types. For example, in the search for oil it is important to separate signals due to producible hydrocarbons from the signal contribution of brine, which is a fluid phase of little interest. However, so far no approach has been advanced to reliably perform such fluid separation.
Various methods exist for performing measurements of petrophysical parameters in a geologic formation. Nuclear magnetic resonance (NMR) logging, which is the focus of this invention, is among the best methods that have been developed for a rapid determination of such parameters, which include formation porosity, composition of the formation fluid, the quantity of movable fluid, permeability among others. At least in part this is due to the fact that NMR measurements are environmentally safe and are unaffected by variations in the matrix mineralogy.
To better appreciate how NMR logging can be used for fluid signal separation, it is first necessary to briefly examine the type of parameters that can be measured using NMR techniques. NMR logging is based on the observation that when an assembly of magnetic moments, such as those of hydrogen nuclei, are exposed to a static magnetic field they tend to align along the direction of the magnetic field, resulting in bulk magnetization. The rate at which equilibrium is established in such bulk magnetization upon provision of a static magnetic field is characterized by the parameter T.sub.1, known as the spin-lattice relaxation time. Another related and frequently used NMR logging parameter is the spin-spin relaxation time T.sub.2 (also known as transverse relaxation time), which is an expression of the relaxation due to non-homogeneities in the local magnetic field over the sensing volume of the logging tool. Both relaxation times provide information about the formation porosity, the composition and quantity of the formation fluid, and others.
Another measurement parameter obtained in NMR logging is the diffusion of fluids in the formation. Generally, diffusion refers to the motion of atoms in a gaseous or liquid state due to their thermal energy. Self-diffusion is inversely related to the viscosity of the fluid, which is a parameter of considerable importance in borehole surveys. In a uniform magnetic field, diffusion has little effect on the decay rate of the measured NMR echoes. In a gradient magnetic field, however, diffusion causes atoms to move from their original positions to new ones, which moves also cause these atoms to acquire different phase shifts compared to atoms that did not move. This contributes to a faster rate of relaxation.
NMR measurements of these and other parameters of the geologic formation can be done using, for example, the centralized MRIL.RTM. tool made by NUMAR, a Halliburton company, and the sidewall CMR tool made by Schlumberger. The MRIL.RTM. tool is described, for example, in U.S. Pat. No. 4,710,713 to Taicher et al. and in various other publications including: "Spin Echo Magnetic Resonance Logging: Porosity and Free Fluid Index Determination," by Miller, Paltiel, Millen, Granot and Bouton, SPE 20561, 65th Annual Technical Conference of the SPE, New Orleans, La., Sep. 23-26, 1990; "Improved Log Quality With a Dual-Frequency Pulsed NMR Tool," by Chandler, Drack, Miller and Prammer, SPE 28365, 69th Annual Technical Conference of the SPE, New Orleans, La., Sep. 25-28, 1994. Details of the structure and the use of the MRIL.RTM. tool, as well as the interpretation of various measurement parameters are also discussed in U.S. Pat. Nos. 4,717,876; 4,717,877; 4,717,878; 5,212,447; 5,280,243; 5,309,098; 5,412,320; 5,517,115, 5,557,200 and 5,696,448, all of which are commonly owned by the assignee of the present invention. The Schlumberger CMR tool is described, for example, in U.S. Pat. Nos. 5,055,787 and 5,055,788 to Kleinberg et al. and further in "Novel NMR Apparatus for Investigating an External Sample," by Kleinberg, Sezginer and Griffin, J. Magn. Reson. 97, 466-485, 1992. The content of the above patents and publications is hereby expressly incorporated by reference.
It has been observed that the mechanisms which determine the measured values of T.sub.1, T.sub.2 and diffusion depend on the molecular dynamics of the formation being tested and on the types of fluids present. Thus, in bulk volume liquids, which typically are found in large pores of the formation, molecular dynamics is a function of both molecular size and inter-molecular interactions, which are different for each fluid. Water, gas and different types of oil each have different T.sub.1, T.sub.2 and diffusivity values. On the other hand, molecular dynamics in a heterogeneous media, such as a porous solid that contains liquid in its pores, differs significantly from the dynamics of the bulk liquid, and generally depends on the mechanism of interaction between the liquid and the pores of the solid media. It will thus be appreciated that a correct interpretation of the measured signals can provide valuable information relating to the types of fluids involved, the structure of the formation and other well-logging parameters of interest.
One problem encountered in standard NMR measurements is that in some cases signals from different fluid phases cannot be fully separated. For example, NMR signals due to brine, which is of no interest to oil production, cannot always be separated from signals due to producible hydrocarbons. The reason is that there is an overlap in the spectra of the measured signals from these fluids (see, for example, FIGS. 4a and 4b showing this overlap in the case of standard brine and hydrocarbon T.sub.2 amplitude spectra).
Several methods for acquiring and processing gradient NMR well log data have been proposed recently that enable the separation of different fluid types. These separation methods are based primarily on the existence of a T.sub.1 contrast and a diffusion contrast in NMR measurements of different fluid types. Specifically, a T.sub.1 contrast is due to the fact that light hydrocarbons have long T.sub.1, times, roughly 1 to 3 seconds, whereas T.sub.1 values longer than 1 second are unusual for water-wet rocks. In fact, typical T.sub.1 's are much shorter than 1 sec, due to the typical pore sizes encountered in sedimentary rocks, providing an even better contrast.
Diffusion in gradient magnetic fields provides a separate contrast mechanism applicable to T.sub.2 measurements that can be used to further separate the long T.sub.1 signal discussed above into its gas and oil components. In particular, at reservoir conditions the self-diffusion coefficient D.sub.0 of gases, such as methane, is at least 50 times larger than that of water and light oil, which leads to proportionately shorter T.sub.2 relaxation times associated with the gas. Since diffusion has no effect on the T.sub.1 measurements, the resulting diffusion contrast can be used to separate oil from gas.
The T.sub.1 and diffusion contrast mechanisms have been used to detect gas and separate different fluid phases in what is known as the differential spectrum method (DSM) proposed first in 1995. The original DSM uses two standard single-echo spacing logs acquired at different wait times in two separate passes. The short wait time T.sub.WS is chosen large enough to allow full recovery of the brine signal, i.e., T.sub.WS &gt;3 max (T.sub.1,water) , while the long wait time T.sub.WL is selected such that T.sub.WL &gt;T.sub.1 of the light hydrocarbon, usually assumed to be gas. At each depth, the differential spectrum is formed by subtracting the T.sub.2 distribution measured at T.sub.WS from the one measured at T.sub.WL. Because T.sub.1 recovery of the water signal is essentially complete at both wait times, this signal is eliminated following the substraction, and the differential spectrum is therefore due only to a hydrocarbon signal. While the DSM method has been applied successfully for the detection of gas and the separation of light hydrocarbons, there are several problems associated with it that have not been addressed adequately in the past.
First, DSM requires a logging pass associated with relatively long wait times (T.sub.W approximately 10 sec). Accordingly, DSM-based logging is by necessity relatively slow.
DSM's use of T.sub.1 contrast may cause additional problems. For example, the required T.sub.1 contrast may disappear in wells drilled with water-based mud, even if the reservoir contains light hydrocarbons. This can happen because water from the mud invades the big pores first, pushing out the oil and thus adding longer T.sub.2 's to the measurement spectrum. In such cases, DSM or standard NMR time domain analysis (TDA) methods have limited use either because there is no separation in the T.sub.2 domain, or because the two phases are too close and can not be picked robustly.
Separation problems similar to the one described above can also occur in carbonate rocks. In carbonates an overlap between the brine and hydrocarbons phases is likely because the surface relaxivity in carbonates is approximately 1/3 that of sandstones. In other words, for the same pore size, the surface relaxation in carbonates is about 3 times longer than that for a sandstone, such weak surface relaxation causing an overlap between the observable fluid phases.
Additional problem for carbonates is the presence of vugs. Water bearing vugs, because of their large pore sizes, have long T.sub.2 's and can easily be interpreted as oil by prior art techniques.
It is apparent, therefore, that there is a need for a new system and method for NMR borehole measurements in which these and other problems are obviated, and better separation is provided between NMR signals from producible oil and interfering signals from brine-type fluids.